The present disclosure relates generally to petrophysically-regularized nuclear magnetic resonance inversion and, more particularly, to petrophysically-regularized nuclear magnetic resonance inversion in the time domain using a porosity input for unconventional reservoirs in organic shales.
The focus of petroleum industry activity in North America in the last 3 to 4 years has migrated from gas shale to liquid (e.g., oil producing) shale. There are differences in the properties of the liquid hydrocarbon phase versus the gaseous hydrocarbon phase and, thus, differences in the resulting interactions between the fluids and the rock matrix. Therefore, production and evaluation models developed for gas may not be directly applicable to oil.
Production of oil from organic shale reservoirs is a combination of two major factors: reservoir quality and completions quality. Reservoir quality is a function of porosity, hydrocarbon saturation, pore pressure, and matrix permeability, while completions quality is a function of hydraulic fracture surface area and fracture conductivity. Hydraulic fracture surface area, porosity, saturations of various fluids, and pore pressure dominate initial production rates. However, to sustain production later in the time matrix, permeability becomes increasingly relevant. The permeability of oil from organic shale is believed to be a function of pore throat size, wettability, and water saturation, which is the same as a conventional reservoir. Nuclear magnetic resonance (“NMR”) logging is the primary method in the industry to characterize these reservoir parameters, and it has recently been used for unconventional reservoirs in organic shale.
One proposed technique for pore partitioning in carbonates with NMR logs is guided by mercury injection capillary pressure test (“MICP”) data. This technique has subsequently been developed into CIPHER℠—a petrophysically regularized time domain NMR inversion—that has demonstrated success in a blind field test with data from Arab limestone. The method used in CIPHER℠ is decomposition of NMR T2 distribution into a number of Gaussian components. These Gaussian components obtained from the T2 distribution are attributed to different porobodons. The term “porobodon” postulates the relationship between the NMR relaxation time spectrum and porositon, which in turn is a distinct and separable distribution in maximum pore throat diameters space. CIPHER℠ performs stochastic inversion in the space of pulse decay curves based on a porobodon/porositon approach with petrophysical restrictions. It overcomes problems with the biased commercial NMR T2 distribution and provides uncertainty estimates for the inversion results. These uncertainty estimates are used to determine the petrophysical restriction mentioned above. However CIPHER℠ does not include total porosity information as a factor guiding inversion.
A challenge for NMR based reservoir characterization in organic shale is low sensitivity of NMR logs to the short time part of NMR relaxation time distribution, particularly in the range of T2 below about 0.2-0.3 ms. The low sensitivity leads to the deficit in log T2 distributions versus the core in short ranges as well to total porosity deficit in NMR versus the core. It is the short T2 part in the oil bound in the organic shale that is exposed; hence, the whole NMR applicability for reservoir characterization becomes questionable. Improving a signal and/or noise ratio for the first echo and reducing echo spacing alleviates the challenge, but these are quite daunting hardware design tasks. CIPHER℠ has demonstrated success in overcoming similar low sensitivity challenges for long relaxation times with existing hardware. Therefore, a similar technique may be applied for unconventional reservoirs in organic shale.